1. Field of the Invention
This invention relates generally to the identification of corrosive materials in a wellbore penetrating a subsurface formation and, more particularly, to the identification of hydrogen sulfide (H2S) in such a wellbore and contained within formation fluids.
2. Description of Related Art
Hydrocarbon fluids such as oil and natural gas are obtained from a subterranean geologic formation, referred to as a reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation. Once a wellbore has been drilled, the well must be completed before hydrocarbons can be produced from the well. A well completion involves the design, selection, and installation of equipment and materials in or around the wellbore for conveying, pumping, and/or controlling the production or injection of fluids. After the well has been completed, production of oil and gas can begin.
In the construction of hydrocarbon production, processing and transportation facilities, it is often desirable to know whether corrosive materials are contained within the formation fluids in order to select the appropriate materials for the design of wellbore completions, pipelines and related facilities. In particular, it may be necessary to know the concentration of any hydrogen sulfide contained within the formation fluids if the proper materials are to be used.
The desirability of taking downhole formation fluid samples for chemical and physical analysis has long been recognized by oil companies, and such sampling has been performed by the assignee of the present invention, Schlumberger, for many years. Samples of formation fluid, also known as reservoir fluid, are typically collected as early as possible in the life of a reservoir for analysis at the surface and, more particularly, in specialized laboratories. The information that such analysis provides is vital in the planning and development of hydrocarbon reservoirs, as well as in the assessment of a reservoir's capacity and performance.
The process of wellbore sampling involves the lowering of a sampling tool, such as the MDT™ formation testing tool, owned and provided by Schlumberger, into the wellbore to collect a sample or multiple samples of formation fluid by engagement between a probe member of the sampling tool and the wall of the wellbore. The sampling tool creates a pressure differential across such engagement to induce formation fluid flow into one or more sample chambers within the sampling tool. This and similar processes are described in U.S. Pat. Nos. 4,860,581; 4,936,139 (both assigned to Schlumberger); U.S. Pat. Nos. 5,303,775; 5,377,755 (both assigned to Western Atlas); and U.S. Pat. No. 5,934,374 (assigned to Halliburton).
The metals comprising the MDT tool and other known formation testing tools are known to react with any hydrogen sulfide (H2S) in the fluid coming from the formation. Because of this reaction, when a fluid sample from the MDT tool (which will be described for illustrative purposes hereinafter) is subsequently analyzed, the measured concentration of H2S in the sample is lower than the concentration of H2S in the reservoir fluid. If the concentration of H2S in the reservoir fluid is sufficiently low, the concentration in the fluid sample can have no measurable H2S.
Customers (i.e., oil companies) often want to know the concentration of H2S in order to select the appropriate materials for the design of completions, pipelines and facilities. H2S—resistant materials can be 5–50 times more expensive than non-resistant materials, so money is wasted if they are used but not needed. The consequences may be worse if they are not used but were needed. Normally, in the latter cases, production is stopped, an expensive well intervention is required, and then the expensive materials must be used.
It difficult, if not impossible and/or impracticable, to correct the concentration of H2S in the sample for that which was lost due to reaction with the metal in the MDT tool. The mechanisms are too complex and depend on concentration, materials, pressure, temperature, history, etc. Furthermore, if there is no H2S in the sample, it is usually not possible to tell if there was H2S in the reservoir fluid or not.
An alternative would be to make the MDT tool non-reactive, or inert, to H2S. A bottom-hole sampler can be thought of as a sample bottle that sits in the production stream. The seal valve opens, the bottle fills and the bottle re-seals. If the inner walls of the bottle are coated or passivated in some manner, then the H2S concentration of the fluid that enters the bottle will remain in the fluid. In this way, a lab analysis can determine the concentration of H2S in the reservoir fluid.
The MDT tool differs in that fluid is pumped along the flowline, through the displacement unit, and then out to the wellbore for an extended period of time, prior to the sample being captured in a bottle. If at the time when the sample is to be captured, the concentration of H2S at the location of the sample chamber is equal, or close to, the concentration of H2S entering the distant probe, then it may be sensible to coat or passivate an MDT tool bottle to preserve the concentration. If, however, the concentration of H2S at the location of the sample chamber is lower than the level in the formation, then there is no point attempting to preserve the H2S in the sample. (It may not be realistic to consider coating or passivating the entire flow path from the probe to the sample bottle.) In this case, a downhole H2S sensor positioned close to the sandface, may be required.
Tests have been performed to determine if a coated sample bottle will meet the customer need, or whether a downhole sensor will be required. To make this decision, tests of the H2S loss within the flowline and displacement unit my be experimentally measured. The results show that the loss of H2S within the flowline and in the displacement unit is significant. Hence, a downhole sensor located near the probe is deemed desirable.
Sulfide Stress Cracking
Sulfide stress cracking (stress corrosion cracking, hydrogen embrittlement) refers to the combination of hydrogen sulfide and water reacting with metal to form micro-cracks. These cracks weaken the material. If the material is also under tensile stress, the strength of the material may reduce to the point of failure. This form of corrosion is unlike ‘weight loss’ CO2 induced mechanisms of corrosion, in which the metal dissolves, lowering its strength until failure occurs.
If the material is not under tensile load, or if there is no water present, then the presence of hydrogen sulfide will usually not cause material failure.
NACE MR0175 states that an H2S partial pressure of 0.05 psi or more requires the use of H2S—resistant materials. A graphical depiction of the NACE specification is shown in FIG. 1.
The relationship between partial pressure and concentration is set forth below:Partial Pressure=Concentration×Absolute PressureFor example, a concentration of 10 ppm is 10/1,000,000 or 1×10−5. For an absolute pressure of 10,000 psi, the partial pressure is 10,000×10−5=0.1 psi. Therefore, 10 ppm at 10 kpsi is twice the NACE MR0175 limit of 0.05 psi. This example corresponds to the point A on the plot SHOWN in FIG. 1.
As mentioned above, sulfide stress cracking of will not occur without water (and tensile stress) also being present. Since the development of MR0175, it has been discovered that the severity of the problem depends on the pH of the water, in addition to the partial pressure of H2S. This is illustrated in FIG. 2. Region 0 (below 0.05 psi partial pressure) is referred to as ‘sweet’, and no special resistant materials are required. Regions 1, 2 and 3 of FIG. 2 are referred to as ‘mild sour’, ‘intermediate sour’ and ‘severe sour’, and materials with increasing levels of resistant materials are required.
H2S-Resistant Materials
The word ‘H2S resistant’ means that the material does not form micro-cracks that weaken the material. However, the material may still ‘react’ with H2S. Thus, a non-reactive or inert, material is also H2S—resistant, but the reverse may not be true.
Leading Causes of Mechanical Failure
The leading causes of mechanical failure of materials in the oil and gas industry are estimated as follows:
28%CO2 corrosion18%H2S sulfide stress cracking18%welding15%pitting12%erosion 6%galvanic 3%stress.
Sulfide stress cracking is estimated to be the second leading cause of mechanical failure.
The consequences of a mechanical failure to the customer are generally severe. A failure within a production facility at surface may require that the production be stopped. A failure in a well completion or a sub-sea pipeline requires a much more difficult and expensive intervention, in addition to shutting in the production.
Cost of H2S—Resistant Materials
Referring now to FIG. 3, the table shows the cost in dollars per pound of various alloys. The more expensive alloys are H2S resistant and range from 10 to 60 times more than the least expensive, which are not H2S resistant. Hence, customers often wish to know whether or not the expensive alloys are needed. The consequence of using of these expensive materials in a case where they are not needed is a significant wasted capital expenditure. The consequence of not using them in a case where they are needed may be much worse.
Experiment Design and Results
The merits of an experimental approach have been documented. For example, tests have been done at 1000 psi and 300 deg F. Nitrogen gas, water vapor and 50 ppm H2S were used as the test fluid. This corresponds to a partial pressure of 0.05 psi, which is the threshold between ‘sweet’ and ‘sour’.
There were 4 series of tests conducted:                1. Flowline MONEL® test        2. Flowline titanium test        3. Elastomer test        4. Displacement unit test        
The flowline tests were conducted by flowing the fluid through 20 feet of tubing at a flowrate of 1 liter/minute. The concentration of H2S at the output was measured periodically by sampling the output. The sampling was frequent at early times, and less frequent at late times.
The test duration was 4 hours. Two different tubings were tested, and a repeat test was done on one of the two tubings.
FIGS. 4 and 5 are rcpresentative of the behavior of the MONEL® and Titanium sections of the flowline, respectively. Here we see that, after pumping 50 ppm H2S through the MONEL® tube for 4 hours, only 12 ppm is coming out, while the Titanium is nearly non-reactive.
Elastomer buttons and slabs were tested for their tendency to ‘soak up’ H2S with time. The buttons had 80% less area and 50% less volume than the slabs. The results depicted in FIGS. 6 and 7 show little absorption over 10 minutes, but considerable absorption over 1000 minutes (16 hours). The difference in absorption between the slabs and the buttons was 30%, which is closer to the difference in volume than the difference in area. Therefore, the absorption is more of a volume effect (i.e. a sponge-like behavior).
The displacement unit differs from the flowline in that the fluid is resident on the same material for roughly 30 seconds. The displacement unit is made from both MONEL® and Aluminum-Bronze, and it clear from FIG. 8 that the displacement unit extracts 16 ppm of the H2S within 30 seconds and all 50 ppm of the H2S from the fluid within an hour.
Customers may need to know the concentration of hydrogen sulfide in the reservoir fluid. Fluid samples from the MDT tool contain a concentration of H2S that is less than that of the reservoir fluid. One solution would be to develop an ‘inert’ or ‘non-reactive’ sample bottle that can preserve the concentration of H2S in the fluid. However this only makes sense if the reaction along the flowline, and within the displacement unit, have not already reduced the concentration of H2S. If the concentration of H2S at the location of the sample bottle is not equal (or close to) the concentration entering the probe, then an H2S sensor positioned near the sandface may be required.
A series of flowline, elastomer and displacement unit tests were concluded. The results indicate that both the displacement unit and the MONEL® sections of the flowline react significantly with any H2S in the fluid. Therefore, even after a significant pump-out period, the concentration of H2S at the location of the sample bottle may not be representive of the level which is entering the probe. An H2S sensor positioned near the sandface may be required. Thus, the development of a non-reactive bottle may be desirable.
If H2S is present in an MDT tool fluid sample in a PVT lab analysis (or at the well site), there may be a higher concentration of H2S in the reservoir fluid, and may be an issue for both personal safety and materials selection. If H2S is not present in an MDT tool fluid sample, then it will often be unclear if there is enough H2S present in the reservoir fluid to pose a risk to personal safety, or to require special materials selection.
Various techniques have been developed to detect Hydrogen Sulfide in wellbore applications. Such techniques include at least the following: gas chromatography, potentiometrics, cathode stripping, spectrophotometry, spectroscopy, reflectivity, fluorescent reagents, biosensors, chemical sensors, etc. as described in PCT International Application No. PCT/GB/0011 to Jiang et al. published on Aug. 30, 2001, the entire contents of which is hereby incorporated by reference. Some techniques, such as PCT International Application No. PCT/GB/0011 and U.S. Pat. No. 6,223,922 B1 issued on May 1, 2001 to Jones, the entire contents of which are hereby incorporated by reference, relate to downhole operations. The current means of taking fluid samples for hydrogen sulfide analysis can alter the hydrogen sulfide content in the sample and can provide the operator with erroneous results that cannot be relied on.
There remains a need for downhole sensors that can measure H2S concentration in fluid under temperature and pressure. The present invention addresses these shortcomings.